To prepare a well for production of hydrocarbons, various operations are performed, including drilling and completion operations. In drilling a well, a drill bit is carried on the end of a drill pipe. In completing a well, various operations may be performed by carrying tools down on a tubing string (e.g., a coiled tubing or jointed tubing). As used here, the term “tubing string” is used to denote a rigid conveyance mechanism or structure, such as a coiled tubing or drill pipe, that can be used to carry tools or fluids into a wellbore.
More recently, many deviated or extended reach wells have been drilled to facilitate the recovery of hydrocarbons. Extended reach wells have proven to be able to increase the recovery rate of hydrocarbons while reducing the operational cost. Generally, the deeper an extended reach well can be drilled or serviced, the higher the economic benefit. Despite many technical advances in the area of extended reach technology, challenges remain in drilling or servicing extended reach wells.
For a given extended or deviated well, the reach of a tool carried on a tubing string is limited by the propensity of the tubing string to lock up. As a tubing string is run into a wellbore, it has to overcome the frictional force between the tubing string and the wall of the wellbore. The longer the length of the tubing string that is run into the wellbore, the greater the frictional force that is developed between the tubing string and the wellbore wall. When the frictional force becomes large enough, it will cause the tubing string to buckle, first into a sinusoidal shape and then into a helical shape. After helical buckling occurs, continuing to run the tubing string into the wellbore will eventually lead to a stage where further pushing of the tubing string will not result in further advancement of the tubing string. Such a stage is referred to as tubing string lockup. The depth of tubing string lockup defines the maximum depth a tool or fluid can be delivered in the well.
Various factors affect (directly or indirectly) the maximum depth that a tubing string can be run into a wellbore. One factor is the friction coefficient between the tubing string and the wellbore. Another factor is the normal contact force between the tubing string and the wellbore, which is dependent on the weight of the tubing string and the stiffness of the tubing string. Generally, a lower friction coefficient or lower tubing string weight usually indicates that the tubing string can extend further into the wellbore. Also, higher bending stiffness tends to delay the occurrence of buckling, which extends the reach of the tubing string into the wellbore.
Various solutions have been attempted or implemented to extend the reach of a tubing string in a wellbore. One is to reduce the contact force between the tubing and the wellbore, such as by using different fluids inside and outside the tubing to reduce the buoyancy weight of the tubing or by using a more light-weight material for the tubing. Another technique is to delay or prevent the onset of helical buckling, which can be achieved by using larger diameter tubing. However, this increases the weight of the string and reduces flexibility in operation. Yet another approach uses a tractor to pull tubing into the well by applying a tractor load at the lower end of the tubing. Other approaches employ vibration to aid in friction reduction.
However, despite the various solutions that have been proposed or implemented, a need continues to exist for an improved method and apparatus to improve the reach of a string in a wellbore.